This invention relates generally to the completion of wellbores. More particularly, this invention relates to new and improved methods and devices for completion, extension, fracing and increasing rate of penetration (ROP) in drilling of a branch wellbore extending laterally from a primary well which may be vertical, substantially vertical, inclined or horizontal. This invention finds particular utility in the completion of multilateral wells, that is, downhole well environments where a plurality of discrete, spaced lateral wells extend from a common vertical wellbore.
Horizontal well drilling and production have been increasingly important to the oil industry in recent years due to findings of new or untapped reservoirs that require special equipment for such production. While horizontal wells have been known for many years, only relatively recently have such wells been determined to be a cost effective alternative (or at least companion) to conventional vertical well drilling. Although drilling a horizontal well costs substantially more than its vertical counterpart, a horizontal well frequently improves production by a factor of five, ten, or even twenty of those that are naturally fractured reservoirs. Generally, projected productivity from a horizontal well must triple that of a vertical hole for horizontal drilling to be economical. This increased production minimizes the number of platforms, cutting investment and operational costs. Horizontal drilling makes reservoirs in urban areas, permafrost zones and deep offshore waters more accessible. Other applications for horizontal wells include periphery wells, thin reservoirs that would require too many vertical wells, and reservoirs with coning problems in which a horizontal well could be optimally distanced from the fluid contact.
Horizontal wells are typically classified into four categories depending on the turning radius:
1. An ultra-short turning radius is 1-2 feet; build angle is 45-60 degrees per foot.
2. A short turning radius is 20-100 feet; build angle is 2-5 degrees per foot.
3. A medium turning radius is 300-1,000 feet; build angle is 6-20 degrees per 100 feet.
4. A long turning radius is 1,000-3,000 feet; build angle is 2-6 degrees per 100 feet.
These additional lateral wells are sometimes referred to as drainholes and vertical wells containing more than one lateral well are referred to as multilateral wells. Multilateral wells are becoming increasingly important, both from the standpoint of new drilling operations and from the increasingly important standpoint of reworking existing wellbores including remedial and stimulation work.
As a result, the foregoing increased dependence on and importance of horizontal wells, horizontal well completion, and particularly multilateral well completion, important concerns provide a host of difficult problems to overcome. Lateral completion, particularly at the juncture between the vertical and lateral wellbore is extremely important in order to avoid collapse of the well in unconsolidated or weakly consolidated formations. Thus, open hole completions are limited to competent rock formations; and even then open hole completions are inadequate since there is no control or ability to re-access (or re-enter the lateral) or to isolate production zones within the well. Coupled with this need to complete lateral wells is the growing desire to maintain the size of the wellbore in the lateral well as close as possible to the size of the primary vertical wellbore for ease of drilling and completion.
Conventionally, horizontal wells have been completed using either slotted liner completion, external casing packers (ECP's) or cementing techniques. The primary purpose of inserting a slotted liner in a horizontal well is to guard against hole collapse. Additionally, a liner provides a convenient path to insert coiled tubing in a horizontal well. Three types of liners have been used namely (1) perforated liners, where holes are drilled in the liner, (2) slotted liners, where slots of various width and depth are milled along the line length, and (3) pre-packed liners.
Slotted liners provide limited sand control through selection of hole sizes and slot width sizes. However, these liners are susceptible to plugging. In unconsolidated formations, wire wrapped slotted liners have been used to control sand production. Gravel packing may also be used for sand control in a horizontal well. The main disadvantage of a slotted liner is that effective well stimulation can be difficult because of the open annular space between the liner and the well. Similarly, selective production (e.g., zone isolation) is difficult.
Another option is a liner with partial isolations. External casing packers (ECPs) have been installed outside the slotted liner to divide a long horizontal well bore into several small sections. This method provides limited zone isolation, which can be used for stimulation or production control along the well length. However, ECP's are also associated with certain drawbacks and deficiencies. For example, normal horizontal wells are not truly horizontal over their entire length; rather they have many bends and curves. In a hole with several bends it may be difficult to insert a liner with several external casing packers. Finally, it is possible to cement and perforate medium and long radius wells as shown, for example, in U.S. Pat. No. 4,436,165.
While sealing the juncture between a vertical and lateral well is of importance in both horizontal and multilateral wells, re-entry and zone isolation is of particular importance and pose particularly difficult problems in multilateral wells completions. Re-entering lateral wells is necessary to perform completion work, additional drilling and/or remedial and stimulation work. Isolating a lateral well from other lateral branches is necessary to prevent migration of fluids and to comply with completion practices and regulations regarding the separate production of different production zones. Zonal isolation may also be needed if the borehole drifts in and out of the target reservoir because of insufficient geological knowledge or poor directional control; and because of pressure differentials in vertically displaced strata as will be discussed below.
When horizontal boreholes are drilled in naturally fractured reservoirs, zonal isolation is seen as desirable. Initial pressure in naturally fractured formations may vary from one fracture to the next, as may the hydrocarbon gravity and likelihood of coning. Allowing different fractures to produce together, permits cross flow between fractures and a single fracture with early water breakthrough, which may jeopardize the entire well's production.
As mentioned above, initially horizontal wells were completed with uncemented slotted liner unless the formation was strong enough for an open hole completion. Both methods make it difficult to determine producing zones and, if problems develop, practically impossible to selectively treat the right zone. Today, zone isolation is achieved using either external casing packers on slotted or perforated liners or by conventional cementing and perforating.
The problem of lateral wellbore (and particularly multilateral wellbore) completion has been recognized for many years as reflected in the patent literature. For example, U.S. Pat. No. 4,807,704 discloses a system for completing multiple lateral wellbores using a dual packer and a deflective guide member. U.S. Pat. No. 2,797,893 discloses a method for completing lateral wells using a flexible liner and deflecting tool. U.S. Pat. No. 2,397,070 similarly describes lateral wellbore completion using flexible casing together with a closure shield for closing off the lateral. In U.S. Pat. No. 2,858,107, a removable whipstock assembly provides a means for locating (e.g., re-entry) a lateral subsequent to completion thereof.
Notwithstanding the above-described attempts at obtaining cost effective and workable lateral well completions, there continues to be a need for new horizontal wells to increase, for example, unconventional shale plays—which are wells exhibiting low permeability and therefore requiring horizontal laterals increasing in length to maximize reservoir contact. With increased lateral length, the number of zones fractured increases proportionally.
Most of these wells are fractured using the “Plug and Perf” method which requires perforating the zone nearest the toe of the horizontal section, fracturing that zone and then placing a composite plug (pumped down an electrical line) followed by perforating the next set of cluster. The process is repeated numerous times until all the required zones are stimulated. Upon completing the fracturing operation, the plugs are removed with a positive displacement motor (PDM) and mill run on coiled tubing. As the lateral length increases, milling with coiled tubing becomes less efficient, leading to the use of jointed pipe for removing plugs.
Two related reasons cause this reduction in efficiency of the CT. First, as the depth increases, the effective maximum weight on bit (WOB) decreases. Second, at increased lateral depths, the coiled tubing is typically in a stable helical spiral in the wellbore. The operator sending the additional coiled tubing (and weight from the surface) will have to overcome greater static loads leading to a longer and inconsistent transmission of load to the bit. This phenomenon is referred to as “stick/slip” in field operations. The onset of these two effects is controlled by several factors including; CT shell thickness, wellbore deviation and build angle, completion size, CT/completion contact friction drag, fluid drag, debris, and bottomhole assembly (BHA) weight and size. CT outer diameter less than 4 inches tends to buckle due to easier helical spiraling, thus increasing the friction from the increased contact surface with the wall of the bore hole. CT outer diameter above 4 inches is impractical due to weight and friction limitations, wellbore deviation is normally not well controlled, friction drag is a function of CT shell thickness and diameter, leaving end loads as one of the variables most studied for manipulation to achieve better well completion.